Produced fluids (fluids are defined as liquids and gases) coming from a wellbore in the oil and gas industry are drawn from subterranean formations. The formation itself tends to restrict the flow of its own fluids, and the industry has defined a parameter which measures the tendency of fluids to flow under unequal pressure within a formation called permeability. Thus, the industry is interested in the permeability of a producing formation and employs techniques to maximize the permeability. There are several factors which affect the permeability of the formation which includes the effect of pores (the interstitial structure of the formation--namely voids, holes and other spaces), the effect of other fluids within the formation, and the effect of pore throats. Pore throats are essentially small pores within the formation.
After the actual drilling of a wellbore is complete, and if the well is successful, the industry performs an operation called completion. Completion is a series of involved operations and includes casing of the wellbore (running a steel tube from basically the bottom of the wellbore to the surface), cementing the casing in place within the wellbore (this operation fills voids between the steel casing and the formation strata and assures that one or more zones will not be in direct communication except through casing perforations), explosive perforation of the casing (punching holes through the steel tube and cement into the subterranean formation at the points where produced fluids are located), followed by cleaning and stimulation of the particular producing formation or formations.
Perforation involves the controlled explosive release of gases which are designed to penetrate the casing, penetrate any cement, and penetrate the subterranean formation immediately to next to the casing. The penetration into the formation is dependent on the size of the charge, the type of formation (sand, sandstone, etc.), the size and thickness of the casing, and myriad other parameters; thus, the perforation extending from the casing into the formation ranges from a couple of inches to several feet. The term "perforation " as used in the industry generally refers to the holes punched in the casing. It is assumed that the perforation operation will "punch" circular holes through the casing and cement into the formation. Most of the time this assumption is true; however, perforations can be irregular in shape.
After the perforation operation is complete, and as part of well completion the wellbore and the producing formation (or formations, in the case of multiple zones) must be cleaned and prepared for production. This series of operations are designed to remove remaining wellbore cuttings (the ground formation strata due to the drilling operation), remaining drilling fluids which are trapped behind the casing and in the production zone or zones, and stimulate the production by increasing the permeability. These operations are run from the surface and involve pumping various fluids, including acids, surfactants and other stimulation and cleaning fluids, down the wellbore into the production formation. The fluids will pass through perforations in the casing and into the formation. After a period of time, pressures are reduced so that the fluid will back-flow and draw impurities back into the wellbore and up to the surface. Sometimes the operator must pressure stimulate the producing zone (or zones) which requires pumping a fluid such as an acid, liquefied gas, a sand slurry, a viscous liquid, or another liquid into the wellbore under high pressure. The high pressure fluid flows through the casing and cement perforations and into the formation where the high pressure causes the formation to crack or fracture; hence, the name fracturing is used to describe this operation.
There is one substantial drawback in the initial cleaning and stimulation operations. The fluids will readily flow through the casing perforations and into the formation wherever the formation permeability is high. Thus, wherever the permeability is low, and treatment is a necessity, cleaning and stimulation fluids will not penetrate and extra pressure will be required to force the fluids into the formation. This extra pressure will in turn force additional fluids into zones which already have high permeability and could damage those zones by fracturing them. In the case of acid fracturing (a high pressure operation) the possibility of damage to production formation is substantially increased. Thus, a method for diverting, controlling or directing the flow of stimulation or cleaning fluids into the formation through casing perforations is required.
After the wellbore is placed in service and as the produced fluids flow through the formation, the produced fluids draw other materials along which often precipitate out (or just drop out) of the fluid. These materials will block the pores; thus, decreasing the permeability over time.
After a period of time, the operator of the wellbore must return to the site and retreat the formation to improve the permeability. These secondary stimulation treatments are similar to the initial treatments and generally include acids and surfactants, both of which are pumped into the wellbore and into the formation. During these secondary treatment operations, the areas of the formation where the permeability has decreased should be treated. Unfortunately, the treating fluids will flow most readily into the formation with the highest permeability--namely where the fluids are not needed, which is the same problem encountered during the initial treatment. In limited cases fracturing is again used and the danger of formation damage reappears. Thus, it is desirable to control or divert fluid flow into the regions with high permeability while forcing the fluids into regions of low permeability.
The industry has developed a product and method to control and direct treatment fluids through casing perforations and into the production zone or zones. The product is called a ball sealer: in reality a series of ball sealers which are capable of plugging the casing perforations. The ball sealers are slightly larger than the casing perforation and are capable of shutting off fluid flow through the casing perforation if and when they fall in front of a perforation. (The art is placing the sealers in the wellbore so that they will seal a perforation at the right time.) The associated method involves pumping the ball sealers into the wellbore along with the treatment fluids in an orderly manner so that they plug the offending perforation at the right time.
The standard method of use requires that the ball sealers be staged in the stimulation fluid as it is pumped into the wellbore. For example, assume that a simulation treatment requires 24 barrels (1,000 gallons) of fluid, and it is known that there are 24 perforations in the wellbore; thus 48 balls will be required. (The operator generally doubles the number of perforations to determine the number of balls.) In this example, the operator would release one ball for each one-half barrel pumped into the wellbore. This will help assure that each perforation is treated with an adequate amount of stimulation fluid before the next ball contacts the next perforation sealing it prior to increased fluid pressure breaking down (opening up) the next unsealed perforation and treating the formation associated with that perforation. The sequence of seal a perforation, treat the next, seal that perforation, treat the next, etc. continues until all the perforations have been ideally treated. At the surface, the operator will note a slight increase in pressure as one perforation is sealed and until the next formation opens up under pressure with an associated pressure decrease. The actual order of perforation treatment will not be from bottom to top, but will be associated with the order in which a given formation associated with a given perforation opens up. Ideally, at the end of the operation, all perforations seal and a sharp pressure increase is seen at the surface: this phenomena is called "balling out" and indicates that all perforations have been treated.
Once the initial or secondary operations are complete, the ball sealers fall away from the perforations (due to flow from the formation into the wellbore) and generally remain in the wellbore where they become a nuisance and present operational problems. Most wellbores contain a `rat hole` which is an extension of the wellbore below the lower casing perforation about 20 plus feet in depth. (In some wellbores this rat hole can become filled with debris and no longer exists.) The balls fall into the rat hole, where, under some circumstances one may be picked up by the motion of the produced fluid and carried to surface. At the surface a renegade ball can plug the surface production valves creating a safety hazard. Some operators will place "ball catchers" at the surface to avoid this problem. Often the wellbore operator must reenter the hole with drilling tools and the excess balls surround the drilling pipe or downhole tools jamming the pipe or tools in the wellbore. This results in an expensive "fishing" operation to retrieve the jammed tools.